Production of hydrocarbons (oil and/or gas) from subsea oil/gas wells typically involves positioning several items of production equipment, e.g., Christmas trees, manifolds, pipelines, flowline skids, pipeline end terminations (PLETs), etc. on the sea floor. Flowlines or jumpers are normally coupled to these various items of equipment so as to allow the produced hydrocarbons to flow between and among such production equipment with the ultimate objective being to get the produced hydrocarbon fluids to a desired end-point, e.g., a surface vessel or structure, an on-shore storage facility or pipeline, etc. Jumpers may be used to connect the individual wellheads to a central manifold. In other cases, relatively flexible lines may be employed to connect some of the subsea equipment items to one another. The generic term “flowline” will be used throughout this application to refer to any type of line through which hydrocarbon-containing fluids can be produced from a subsea well.
One challenge facing offshore oil and gas operations involves insuring the flowlines and fluid flow paths within subsea equipment remain open so that production fluid may continue to be produced. The produced hydrocarbon fluids will typically comprise a mixture of crude oil, water, light hydrocarbon gases (such as methane), and other gases such as hydrogen sulfide and carbon dioxide. In some instances, solid materials or debris, such as sand, small rocks, pipe scale or rust, etc., may be mixed with the production fluid as it leaves the well. The same challenge applies to other subsea flowlines and fluid flow paths used for activities related to the production of hydrocarbons. These other flowlines and flow paths could be used to, for example, service the subsea production system (service lines), for injecting water, gas or other mixture of fluids into subsea wells (injection lines) or for transporting other fluids, including control fluids (control lines).
One problem that is sometimes encountered in the production of hydrocarbon fluids from subsea wells is that a blockage may form in a subsea flowline or in a piece of subsea equipment. In some cases the blockage can completely block the flowline/equipment while in other cases the blockage may only partially block the flowline/equipment. For example, the solid materials entrained in the produced fluids may be deposited during temporary production shut-downs, and the entrained debris may settle so as to form all or part of a blockage in a flowline or item of production equipment. Another problem that may be encountered is the formation of hydrate blockages in the flowlines and production equipment.
In general, hydrates may form under appropriate high pressure and low temperature conditions. As a general rule of thumb, hydrates may form at a pressure greater than about 0.47 MPa (about 1000 psi) and a temperature of less than about 21° C. (about 70° F.), although these numbers may vary depending upon the particular application and the composition of the production fluid. Subsea oil and gas wells that are located at water depths greater than a few hundred feet or located in cold weather environments, are typically exposed to water that is at a temperature of less than about 21° C. (about 70° F.) and, in some situations, the surrounding water may only be a few degrees above freezing. Although the produced hydrocarbon fluid is relatively hot as it initially leaves the wellhead, as it flows through the subsea production equipment and flowlines, the surrounding water will cool the produced fluid. More specifically, the produced hydrocarbon fluids will cool rapidly when the flow is interrupted for any length of time, such as by a temporary production shut-down. If the production fluid is allowed to cool to below the hydrate formation temperature for the production fluid and the pressure is above the hydrate formation pressure for the production fluid, hydrates may form in the produced fluid which, in turn, may ultimately form a blockage which may block the production fluid flow paths through the production flowlines and/or production equipment. Of course, the precise conditions for the formation of hydrates, e.g., the right combination of low temperature and high pressure is a function of, among other things, the gas-to-water composition in the production fluid which may vary from well to well. When such a blockage forms in a flowline or in a piece of production equipment, either a hydrate blockage or a debris blockage or a combination of both, it must be removed so that normal production activities may be resumed.
FIGS. 1A-1B simplistically depicts one illustrative prior art system 10 and method that has been employed for removing such a blockage from subsea flowlines/equipment. The system 10 comprises a pump module 12, an isolation valve module 12, a subsea flow line 16 and a simplistically depicted blockage 17 positioned in the flow line 16. Also depicted are a downline 18 and a connecting line 20 between the pump module 12 and the isolation valve module 20. Various fluids may be supplied to the system 10 from a surface vessel or platform (not shown) via the downline 18 and, in practice; there may be multiple downlines 18 that are connected to the system 10 as well as multiple lines 20.
Fluid flow in the flow line 16 would normally flow in the direction indicated by the dashed line arrow 19 when the flow line 16 is operational. Once the blockage 17 was detected and its location identified, the system 10 was lowered to the sea floor and coupled to the flow line 16. As depicted, the blockage 17 has an upstream side 17A and a downstream side 17B. To successfully remove blockages and hydrates from pipelines and large volume pressure vessels, the most common methodology is to first inject chemicals to the affected area (in an attempt to chemically dissolve or soften the blockage 17), followed by a repeatedly creating a differential pressure across the blockage 17. Creating the differential pressure across the blockage 17 often involved creating a vacuum or low pressure on one side of the blockage and/or reversing fluid flow in the flow line 16. For example, a first operation would be performed to create a differential pressure across the blockage 17 with the higher pressure being on the downstream side 17B of the blockage 17. Then, a second operation would be performed so as to create a differential pressure across the blockage 17 with the higher pressure being on the upstream side 17A of the blockage 17. Such operations were performed so as to generate alternating “push” and “pull” forces on the blockage 17 in an attempt to mechanically dislodge the blockage 17. Such “push-pull” operations were typically repeated several times to create a back-and-forth mechanical cyclic force to help dislodge the blockage 17.
The pump module 12 comprises one or more pumps (not individually shown) that is adapted to receive chemicals and/or fluids from the surface via the downline 18. As shown in FIG. 1A, the pump module 12 is adapted to be configured and controlled so as to inject those chemicals and/or fluids through the isolation valve module 14 and into the flow line 16 on the downstream side 17B of the blockage 17 as indicated by the arrow 21. The isolation valve module 14 contains a safety shut-in valve to insure safe operations. As shown in FIG. 1B, the pump module 12 is also adapted to be configured and controlled so as to create a relatively low pressure or vacuum on the downstream side 17B of the blockage 17 by pulling fluid from the downstream side 17B of the blockage and pumping the fluid to the surface via the downline 18.
In one particular example, the blockage removal method may involve first injecting chemicals into an area on the upstream side 17A of the blockage 17 in an attempt to chemically dissolve or soften the blockage 17. Thereafter, efforts are undertaken to reduce the pressure on the downstream side 17B of the blockage 17. The area of low pressure serves at least two purposes. First, by exposing the blockage 17, in this case a hydrate blockage, to a lower pressure on its downstream side 17B that is less than the hydrate formation pressure, all or a part of the blockage 17 may essentially “melt” away (via sublimation). Second, the pressure on the downstream side 17B of the blockage 17 may be reduced in an attempt to create a differential pressure across the blockage 17 (with higher pressure being present on the upstream side 17A of the blockage 17) so as to force the production fluid in the flow line 16, with portions of the removed blockage 17 entrained therein to flow in the direction indicated by the arrow 23, i.e., through the pump module 12 and to the surface via the downline 18. As noted above, in performing such operations, the direction of fluid flow to and from the pump module 12 may need to be reversed several times. This is accomplished by various valves positioned in the pump module 12 that are switched from open/close to reverse flow from the isolation valve module 14 to create a vacuum or relatively low pressure on the downstream side 17B of the blockage 17.
On illustrative example of a prior art pump module 12 that may be employed in connection with removing the blockage from a flow line 16 is depicted in FIGS. 1C-1D. As shown therein, the illustrative pump module 12 is comprised of a pump 30, an inlet 40, and outlet 42, an inlet valve 34 and an outlet valve 36. The inlet valve 34 controls the flow of fluid to the suction side 30S of the pump 30 while the outlet valve 36 controls the flow of fluid from the discharge side 30D of the pump 30. Fluid flows through the pump 30 in the direction indicated by the arrow 31. As shown in FIG. 1C, in one illustrative embodiment, in attempting to remove a blockage from the flow line 16, the pump module 12 may be positioned subsea, and the flow line 16 may be initially coupled to the outlet 42 of the pump module 12 while a down line 18 from a vessel may be initially coupled to the inlet 40 of the pump module 12. Fluids, such as a chemical solution, and increased pressure may be supplied to the downstream side 17B of the blockage 17 by injecting a fluid into the flow line 16. As shown in FIG. 1D, to “reverse” the fluid flow through the flow line 16, the flow line 16 may be decoupled from the outlet 42 of the pump module 12 and coupled to the inlet 40 of the pump module 40, while the down line 18 may be disconnected from the inlet 40 of the pump module 12 and coupled to the outlet 42 of the pump module 12. By disconnecting and recoupling the lines 16, 18 to the inlet 42, outlet 44 of the pump module 12, the flow of the fluid to/from the flow line 16 may be reversed. However, the decoupling and coupling of such flow lines 16 and down lines 18 can be time consuming and expensive and may result in other problems such as damaged seal interfaces due to coupling and decoupling various lines to the pump module 12.
With reference to FIGS. 2A-2B, in smaller scale applications flow reversal to a device such as a pump 24 may be accomplished by the use of two three-way valves 20, 22. In FIG. 2A, the valves 20, 22 are in a first position wherein fluid flow enters the system via line 26 flows to the valve 20 via line 30 where it is directed to the suction side 24S of the pump 24. Fluid flow from the discharge side 24D of the pump 24 flows through the valve 22 and enters line 32 where it ultimately exits the system via line 28. In FIG. 2B, the valves 20, 22 are actuated to a second position wherein fluid flow enters the system via line 28 flows to the valve 20 via line 32 where it is directed to the suction side 24S of the pump 24. Fluid flow from the discharge side 24D of the pump 24 flows through the valve 22 and enters line 30 where it ultimately exits the system via line 26.
The present application is directed to various systems, methods and devices useful in reversing fluid flow to and from various single-flow direction devices that may eliminate or at least minimize some of the problems noted above.